This invention relates generally to a process for the recovery of oil from subterranean formations, and more particularly to a gas flooding or a miscible gas flooding process.
Petroleum or oil is generally recovered from subterranean formations by penetrating the formation with one or more wells and pumping or permitting the petroleum to flow to the surface through the well. In various recovery operations, an external driving force is not required to drive the petroleum to the producing well and/or the surface. For example, some natural driving energy such as an underlying active water drive or a gas under some minimum pressure may possess sufficient pressure to drive the petroleum or hydrocarbon to the well and then to the surface. Recovery of petroleum using natural energy is referred to as primary recovery.
In many instances, the natural driving energy is insufficient or becomes insufficient to cause the petroleum to flow to the well. For example, a substantial portion of the petroleum to be recovered may remain in the formation after depletion of the natural driving energy. In other cases, the subterranean formation, while containing substantial amounts of petroleum, may not possess the necessary driving force to recover any of the petroleum. In such cases, various techniques have been applied heretofore to recover the petroleum. Although such techniques are commonly referred to as secondary recovery, in fact, they may be primary, secondary or tertiary in sequence of employment.
One example of a conventional method for the secondary recovery of petroleum from a subterranean formation involves injecting water or non-miscible gas through one or more injection wells to drive the residual petroleum or oil towards a producing well. A non-miscible gas is one which is not miscible with the hydrocarbons present in the subterranean formation. However, water or non-miscible gas alone do not efficiently displace petroleum. In various operations, the water or non-miscible gas mixture channel through the formation such that a disproportionately high amount of the water or non-miscible gas passes through zones of high permeability into the producing wellbore without contacting appreciable amounts of oil in the reservoir, particularly that oil contained in zones of low permeability. Further, water or non-miscible gas fails to displace even all of the oil in the swept zones because capillary pressure holds residual oil or hydrocarbons in the smaller reservoir capillaries allowing the water or the non-miscible gas to channel around them. This greatly reduces the efficiency of the operation.
One common method of recovering the residual oil trapped in the capillaries of the reservoir after water or non-miscible gas flooding is to contact the residual hydrocarbon with a miscible supercritical fluid. This supercritical fluid is frequently the same as the gas which, under ordinary temperature and pressure is non-miscible, but when subjected to high pressure under the conditions of the subterranean formation becomes a supercritical fluid with which the residual oil is miscible. Thus, under conditions of use, the non-miscible gas used may exist both as a non-miscible gas and as a miscible supercritical fluid. Examples of gases which can exist as supercritical fluids under conditions of use and which are useful in this process include carbon dioxide and mixtures of aliphatic hydrocarbons such as methane, ethane, propane and butane, and may even include nitrogen in very deep wells which can operate under high pressure.
In both the case of gas flood recovery and miscible fluid recovery, the gas or miscible fluid can be injected continuously and simultaneously with water in the same injection well or alternating with slugs of water. Alternatively, the gas or miscible fluid can be injected without water and, in such cases, will frequently form a dispersion with water which naturally exists in the formation or has been injected prior to the gas injection. Although miscible fluid or a simultaneous miscible fluid/water mixture can be employed, miscible fluid or gas flooding generally comprises alternating the injection of miscible gas or fluid and water. In theory, the miscible gas thins or solubilizes the oil from the small capillaries in the formation thus allowing it to flow to the producing well. The water is added to provide some mobility control to the miscible fluid, restricting its advancement to the producing well, thereby causing it to make contact with a larger fraction of the reservoir.
Unfortunately, even in the presence of significant volumes of water, the gas or miscible fluid is prone to channel through the formation such that a disproportionately high amount of the gas or miscible fluid passes through the swept zones of the reservoir into the producing wellbore without contacting appreciable amounts of oil in the reservoir. Further, in miscible flooding operations, this high rate of flow prevents the pressure in at least parts of the reservoir from reaching the minimum pressure necessary to convert the non-miscible gas to a miscible supercritical fluid. This problem is further exacerbated in reservoirs containing zones of high permeability because both the gas or the miscible fluid and the water preferentially proceed to the producing wells by way of these zones. To prevent channeling of the gas or the miscible fluid and the water and to otherwise control the mobility of the drive fluid or the miscible fluid, thereby increasing oil production, it has been suggested to employ a foam prepared from a mixture of water and a surfactant during the gas flooding and/or miscible fluid flooding operations. Such mixtures have been found to prevent channeling and to force the miscible fluids or the gas drive fluids into the unswept and/or less permeable zones of the reservoir, thereby increasing oil production.
Surfactants which have been found to be useful as a means of modifying the profile in gas flooding or miscible fluid flooding operations are surfactants capable of forming a foam with an aqueous liquid and include alkyl polyethylene oxide sulfates (see, for example, U.S. Pat. No. 4,113,011); polyalkoxy sulfonates (see, for example, U.S. Pat. No. 4,502,538); polyalkoxylated alcoholic or phenolic surfactants (see, for example, U.S. Pat. No. 4,380,266) and the like. Mixtures of surfactants, such as a mixture of an alkylated diphenyl sulfonate and an anionic polyoxyalkylated surfactant, (see, for example, U.S. Pat. No. 4,739,831); a mixture of an alkylated diphenyloxide sulfonate and an alpha olefin sulphonate (see, for example, U.S. Pat. No. 4,860,828) or a mixture of amphoteric surfactants and lignosulphonates (see, for example, U.S. Pat. No. 4,703,797) are also taught to be useful.
Surfactants employed in gas flooding operations are exposed to water of relatively low purity such as water having a high dissolved solids content. This is because the connate water is usually highly saline and frequently contains divalent metal ions such as calcium and magnesium. Injected water, when derived from connate water, will have similar impurity content. When fresh water is to be injected, the typical practice is to add salts such as potassium chloride and other potassium salts. It is known in the art that such water soluble salts prevent clay swelling and other undesirable modifications to the oil bearing reservoir which would be caused by fresh water. Thus, in gas flooding operations, it is generally preferred to employ surfactants which are soluble in the presence of moderate to high concentrations of multivalent ions. Thus surfactants successfully employed in foam flood applications where water of low ionic strength is utilized are not necessarily useful in tertiary oil recovery methods using gas flooding techniques.
Dissolved solids are known to increase the adsorption of surfactants to mineral surfaces and therefore it is desirable to employ surfactants which resist this effect. The patent literature describes the use of sacrificial agents such as lignosulfonates to help reduce surfactant adsorption. Such surfactants do not generally improve the foaming qualities of the active foaming surfactants, but merely reduce the amount of the desired surfactant which is adsorbed on the mineral surfaces.
Further, the surfactants heretofore taught to be effective in modifying the mobility of the drive fluids in gas flooding or miscible fluid operations have not proved to be particularly effective in every such operation. Specifically, in certain instances, greater foam stabilities are desired to achieve the desired increase in oil production. In other instances, the surfactants have not been found to be particularly effective in the field regardless of their foaming ability as measured in the laboratory.
Amphoteric surfactants have been suggested for use in enhanced oil recovery processes, particularly where water of high ionic strength is likely to be encountered. This is especially true when the water contains significant concentration of multivalent ions such as calcium. See, for example, U.S. Pat. Nos. 4,130,491, 4,216,097, 4,259,191 and 4,090,969. This is due to the foaming properties of many amphoteric surfactants and the insensitivity of their foaming properties to very high concentrations of dissolved salts in the water. Unfortunately, these surfactants tend to adsorb very strongly to mineral surfaces such as those found in oil reservoirs. For this reason, amphoteric surfactants alone have found very limited utility in foam modified enhanced oil recovery processes. One way of reducing the adsorption of the surfactant is to either preflush the oil reservoir with a sacrificial agent which itself adsorbs to the mineral surface or to co-inject the sacrificial agent with the amphoteric surfactant.
Specific methods of using amphoteric surfactants are discussed in the literature. For example, U.S. Pat. No. 4,703,797 teaches the use of lignosulfonates with amphoteric surfactants. Two major disadvantages exist in relation to the use of sacrificial agents. First, during the co-injection of the amphoteric surfactant and sacrificial agent, the sacrificial agent is depleted as the mixture passes through the formation and eventually, the amphoteric surfactant will encounter mineral surfaces not protected and will itself be adsorbed. Similarly, in the preflush method, unless the oil reservoir is treated with sufficient sacrificial agent to protect all mineral surfaces, the amphoteric surfactant will be adsorbed to the unprotected mineral surfaces with a rapid decrease in its effectiveness. The second major disadvantage is that the sacrificial agent does not necessarily improve the foam forming properties of the amphoteric surfactant and may, in fact, lessen or decrease the effectiveness of the amphoteric surfactant. U.S. Pat. No. 4,703,797 teaches the certain lignosulfonates may be mixed with cocoamidopropyl betaine, an amphoteric surfactant. When mixed in a 50/50 blend, the foaming qualities are similar to the unblended betaine.
In view of the deficiencies of the prior art methods for improving the mobility of the drive fluids in gas flooding or miscible fluid operations, it remains highly desirable to provide a useful new method for controlling the mobility of the drive fluids in gas flooding operations and of miscible fluids in miscible fluid flooding operations.